The present invention relates generally to a method for diagnosing the mechanisms of formation damage in both producing and injection wellbores, and more particularly, to a method for using radially oriented core samples cut from the wellbore wall to diagnose formation damage mechanisms in the wellbores.
Diagnosing formation damage mechanisms in both producing and injecting wells has long been a necessary activity. One of the common ways formation damage mechanisms have been diagnosed in the past is through sampling of scale, sludge, or build-up on production equipment contained in the wellbore, in surface equipment, and/or on tools used in work-over procedures. Samples of the scale, sludge, or build-up can be chemically analyzed to determine what the scale is and what would effectively treat that build-up.
There are some obvious drawbacks to the process utilizing an analysis of the scale. The first drawback is that this method only determines what scale or build-up occurs within the wellbore itself. While this may be an indication of formation damage, it is not a direct measurement of the actual damage mechanisms which are reducing the permeability and porosity of the formation itself. In addition, even if the formation itself is being plugged by scale, build-up, or sludge, there may not be evidence of that build-up anywhere within the wellbore itself or in any of the surface equipment.
Another method of determining formation damage mechanism is to use empirical data gathered from production or injection rates on a particular well or in a given field or reservoir in conjunction with results of past work-over treatments. This method can be used either alone or in conjunction with the analysis of gathered samples mentioned above. In this well-known method, the operator will track either the production or injection rate and look for a significant drop-off in either to indicate that formation damage has occurred. The operator will look for some significant change from the general decline expected in a production well or the constant injection pressures expected in an injection well. For injection wells, the indication of damage may also show up on a pressure versus barrels injected chart as a significant increase in the pressure necessary to inject the same total volume of fluid. Once the operator is alerted to the build-up of damage, he can then review past jobs done either on the particular well or on similar wells in the field to determine what jobs are particularly successful in cleaning up the formation damage. Once again, the method of empirical review has substantial drawbacks. First it is an indirect method of determining formation damage rather than a direct method. Secondly, the assumed basic rate of decline of the given well may actually have incorporated within it some gradual damage build-up that is causing a steeper rate of decline than would occur had there been no damage build-up. Using the empirical method merely attempts to get the well back to the basic rate of decline. Therefore, the use of the empirical method may be leaving a gradual build-up of damage in the well which is not being treated effectively by the methods which have proven to be successful to treat the damage mechanism causing the rapid build-up of formation damage.
Another conventional method of determining what types of formation damage may be occurring is to test well fluids and fluids that have been or will be injected into the wells. One way this is accomplished is to take fluid which is produced from a producing well and mix it with water which is injected in the same reservoir either through injection wells or through well treatments and determine if any precipitate forms when the two fluids are mixed together. If, for example, gypsum scale forms when the two waters are mixed together that is an indication that in the formation gypsum scale may be forming and causing damage.
Another way to use fluid tests is to evaluate the oil which is produced to determine its wax content and its tendency to form paraffin waxes. In addition, the oil may be tested to determine if it has a substantial number of low-end hydrocarbons which may cause a precipitation of a sludge or tar-like substance in the formation.
Once again, the analysis of formation fluids has serious drawbacks in that first, formation conditions can never be truly simulated to determine the actual mixture of the chemicals. Second, the chemicals are not in contact with the free ions that may be released by the formation rock itself. Thirdly, this analysis does not take into account injection of different fluids or chemicals in the past which may have caused formation damage which still exists in the formation. For example, fresh water may have been used in the past, whereas under the current practice of the operator no fresh water ever touches the formation. Finally, this type of analysis does not give any indication of whether there is a mud or filter cake build-up at the formation face nor does it show whether there is a build-up of fines in the formation in the near wellbore region. Once again, this method is merely a projection of what hypothetically might be occurring down in the formation itself.
One particular failing of all the methods mentioned above is that they provide no indication of how deep the formation damage extends out from the wellbore into the formation. Some formation damage may only exist within two inches or less from the wellbore whereas some may extend for up to a foot or more. The extent of the damage would greatly affect the design of a treatment which was directed at correcting that formation damage.
A method that can be used to determine the depth of the formation damage out into the reservoir is a pressure build up test. The pressure build up test is performed by shutting the well in for a number of days or even weeks. The wellbore pressure is then recorded using a pressure bomb and charted against time after shut-in. From the pressure versus time graph a skin factor may be calculated. The skin factor then may be used to calculate the permeability of the damaged zone and the depth which the damaged zone extends out into the formation. The pressure build-up method provides no direct information as to the cause of the formation damage. All that is gained is information concerning the severity and depth of the damage. This method can be very expensive because production or injection must cease completely over the entire testing period. A determination of formation damage by the skin factor method can result in erroneous results. The determined skin factor does not differentiate between a positive skin due to formation damage and other factors that may give a false designation. Such factors include wellbore effects, multi-phase flow, turbulent flow and other effects related to the well completion. Since the skin factor method is an indirect measure of formation damage, no "cause-effect" evaluation can be made from a pressure build-up test.
It is clear with the failings of the current formation damage evaluation systems that a new method for directly evaluating the type, severity, and extent of formation damage is needed.